The present invention relates to a method of downhole separation of produced gas or produced gas and water from produced oil, and re-injection of the gas, or water, or gas and water. The invention also relates to apparatus for use in implementing the method.
In oil and gas production from downhole or earth formations, the produced fluid is extracted via a drilled bore which extends from the surface to intercept the hydrocarbon-bearing formation. In many applications the formation is characterised by the presence of a gas cap which maintains the pressure in the formation, the formation thus being described as gas driven. Effectively the gas drive forces the hydrocarbon liquids and formation water into the well bore and hence to the surface. This is a particular but not exclusive characteristic of condensate-producing formations. Such formations are also often characterised by the presence of fractures or fissures, this resulting in tracking of gas with the reservoir liquids into the well bore and hence production of large volumes of gas with these liquids. Production of these high gas volumes to the surface is often undesirable, firstly because there may be no suitable system for transport to market and the option of flaring is now considered to be environmentally objectionable, and secondly because it is preferable to retain the gas in the formation to maintain formation pressure. In many cases it is also preferred that the produced water be retained in the formation.
Accordingly, many oil production facilities will: flow the formation liquids and gas to the surface; separate the different components; compress the gas; and then inject the gas, and when required the produced water, under pressure, back down into the formation. The gas and water may be transported from surface to the formation either via a separate flow path in the production bore or down another well bore. However, this is inefficient, as a high power input is required to generate the necessary elevated pressures: typically, the pressure of the produced fluids at the reservoir might be 250 bar and at the surface 15 bar, thus necessitating a surface compressor differential of 235 bar.
It is among the objectives of the present invention to obviate or mitigate this and other disadvantages.
According to a first aspect of the present invention there is provided a production fluid handling method comprising the steps:
separating downhole at least gaseous and liquid components of fluid produced from an underground formation; and
at least one of (I) injecting at least a proportion of the gas back into the formation, and (ii) producing at least a proportion of the gas to the surface.
The production or produced fluids in an oil well typically comprise oil and water, or oil, water and gas.
Preferably, the method further comprises separation of the liquid components of the produced fluid, that is the oil and water. At least a proportion of the water may be re-injected back into the formation, or produced to surface.
Alternatives for production, separation and re-injection of produced fluids are summarised in the following table:
Aspects of the present invention may be utilised in the second, third and fourth alternatives.
Preferably, the separation of the components of the produced fluid takes place at or about the same depth as the formation.
Separation of the components of the produced fluid may be achieved by cyclonic separation or other known separation method, however it is preferred to use a horizontal gravity separation process. Such a separation process for oil and water only is described in Norsk Hydro International Patent Application WO98 41304, the disclosure of which is incorporated herein by reference. The process involves passing the produced fluid through a substantially horizontal pipe under conditions, principally related to flow velocity, which allow the different components of the fluid to stratify.
The Norsk Hydro apparatus relates particularly to the production alternative 1 of the above table. All of the other three alternatives require separation of the gas. It has been found that the gas separation can be readily achieved by using a modified form of such an apparatus. The gas separation process may be used on its own if only gas is to be separated from the liquids. Alternatively, if liquid separation is also required, that is if all three fluid components, oil, gas, and water, are to be separated, the gas separation apparatus may be used in combination with the apparatus as described in WO98 41304; that is, a gas liquid separator may be used in combination with an oil water separator.
It has been found that sloping downwards of the gas liquid separator in the direction of flow by a small angle, typically between 1 and 10 degrees, is extremely beneficial in suppressing wave formation, which has a tendency to increase the number of oil droplets in the separated gas. In the absence of wave formation the flow rate through the separator may be significantly increased: it has been found that, for a particular produced fluid, even a 1xc2x0 inclination of the separator allowed the flow rate to be at least doubled.
Preferably, once the gas component is separated from the liquid component, the separated gas may be collected by means of an elongate tube positioned in the gas liquid separator and longitudinally aligned with the direction of flow. Collecting the gas in this manner prevents re-mingling of the gas and liquid after separation since the gas is enclosed within the elongate tube.
Conveniently, the upstream end of the elongate tube is tapered from the tube upper surface to the tube lower surface. Additionally, an array of holes is provided in the upper surface of the elongate tube to allow collection of gas which has passed over the elongate tube. Preferably, the lower surface of the elongate tube gas collector defines a substantially planar surface.
Preferably also, the separated oil and water may be collected by means of respective elongate tubes located within the oil water separator and longitudinally aligned with the direction of flow. Preferably, the oil collector is positioned in an upper portion of the oil water separator and is substantially identical in form to the gas collector.
Conveniently, the water collector is positioned in a lower portion of the oil water separator. Preferably the upstream end of the water collector is tapered from the tube lower surface to the tube upper surface. Preferably also, the lower surface of the water collector comprises an array of holes to collect water which has passed between the water collector and the separator. Preferably, the upper surface of the elongate tube water collector defines a substantially planar surface aligned with the gas liquid interface.
It is desirable that the separated gas which is to be re-injected be virtually free of oil droplets, as many crude oils precipitate solid asphaltene and paraffinic compounds when produced, and these precipitates can cause formation damage that is extremely difficult to remove. Further, formation of such precipitates could, through time, seriously impair injection flow rates. In the preferred embodiments of the invention, the presence of liquid droplets would also have an erosive effect on compressor rotor and stator blades, and for this reason also droplet presence should be minimised.
Oil droplet presence can also be further reduced by incorporating a droplet separator downstream of the gas liquid separator, this droplet separator discharging the so separated liquid into the separated liquid stream from the gas liquid separator. Such a separator may be, for example, either a cyclone or a centrifuge or a static or spinning swirl generator.
Preferably, when it is desirable to re-inject the gas, it is compressed downhole at or around the formation or reservoir depth. Thus, the differential pressure required is only that to overcome the relatively small difference in the static pressure and the injectivity resistance of the reservoir. This pressure difference will be typically 10 bar to 30 bar; the benefits in power performance when compared with compression at the surface, as described previously, will be apparent to those skilled in the art. Thus, the produced gas and, where appropriate, the produced water, may be injected by means of a compressor, or a pump, or a combination of both, directly back into the formation.
The ratios of gas, water and oil present in the produced fluid are likely to change as the formation characteristics vary with time, and thus it is desirable for the separation and re-injection processes and equipment to have the flexibility to accommodate such variation.
It is also desirable to provide control over the quantity of fluids which are produced to the surface and injected into the formation, to accommodate for changes in formation characteristics. Such control may be provided by the use of at least one level monitor located in the downhole separator, said at least one level monitor being utilised to indicate the fluid component levels and initiate signals to adjust flow control valves which may be located at surface level accordingly. The flow control valves may alternatively be located downhole. Preferably, at least one level monitor is located in the gas liquid separator and at least one level monitor is located in the oil water separator, when an oil water separator is provided.
As noted above, it is preferred to compress the produced gas downhole when re-injection is required. Proposals for downhole compressors for boosting depleting gas wells are described in Shell International Patent Application WO97 33070 and Weir Pumps Ltd UK Patent Application 0013449, the former describing an oil-filled motor driven multi-stage gas compressor and the latter a gas filled motor driven multistage gas compressor. Potentially, either of these proposals could be utilised in the present application, however it is preferred that compression of the gas is achieved using a multi-stage axial flow turbine directly coupled to, that is on a single shaft with, a multi-stage axial flow compressor, although other turbine or compressor forms may also be utilised. The preferred compressor is capable of running at high speed, typically in the range 15,000 to 40,000 rpm, to generate the required gas pressures. This avoids the difficulties inherent in, for example, oil-filled motors which cannot run at these speeds, as losses associated with friction and churning are intolerable. Further, although a gas filled motor can be run at high speed, and be directly coupled to the compressor on a single shaft, there would be difficulties associated with high bottom hole pressures and installing the compressor set in what is essentially an oil producing well. However, an axial flow turbine, in the preferred turbine driven compressor solution, may be powered by any suitable liquid delivered under pressure from a surface installed charge pump. In a preferred embodiment the liquid is produced liquid and co-mingles at discharge from the turbine with the produced liquid discharged from the downhole separator. It is advantageous if static heads from surface to the compressor are similar on the flow paths for power liquid from the surface and produced liquid to the surface.
Most preferably, the compressor is arranged such that its discharge end and the turbine exhaust are adjacent to one another. By so arranging, the compressor generated pressure may drive a small amount of compressed gas across a shaft labyrinth seal into the turbine exhaust, which is preferred to having liquid leakage in the opposite direction.
Preferably, the turbine bearings are lubricated by the power liquid and the compressor bearings are lubricated by compressed gas from the compressor discharge, following removal of all residual solids or liquid droplets by a final filtration device which might typically be a cyclone, the residual solids or liquid droplets preferably being returned to either the compressor discharge flow or the compressor inlet.
Further aspects of the present invention also relate to apparatus utilised to implement the methods as described above.